In the development of remote or marginal offshore oil and gas fields, subsea developments are often selected in order to reduce investments in production facilities. Although the hydrocarbons produced on site need processing, the number of subsea process units is preferably low and the units of reduced complexity for minimal maintenance and in order to avoid malfunctions. For further processing it is desirable to utilise process capacity within an hub, infrastructure or on land, which may require transportation over long distances by pipelines.
The hydrocarbon well fluid will often contain both oil and gas which may be transported to different processing units to utilize capacity of surrounding infrastructure. The produced hydrocarbon-containing fluid is warm when entering the wellhead, generally in the range of 60-130° C. and will in addition to hydrocarbons contain liquid water and water in the gas phase corresponding to the water vapour pressure at the current temperature and pressure. If the gas is transported untreated over long distances and allowed to cool, the water in gas phase will condense and below the hydrate formation temperature, hydrates will form. The hydrate formation temperature is in the range of 20-30° C. between 100-400 bara.
Hydrates are ice-like crystalline solids composed of water and gas, and hydrate depositions at the inside wall of gas and/or oil pipelines is a severe problem in today's oil and gas production infrastructure. When warm hydrocarbon fluid containing water flows through a pipeline with cold walls, hydrates will precipitate and adhere to the inner walls. This in turn will reduce the pipeline cross-sectional area, which without proper counter measures will lead to a loss of pressure and ultimately to a complete blockage of the pipeline or other process equipment. Transportation of gas over distance will therefore normally require hydrate control.
Existing technologies that deal with the problem of removing such deposits or avoiding them include:                Mechanical scraping off the deposits from the inner pipe wall at regular intervals by pigging.        Electric heating and insulation keeping the pipeline warm (above the hydrate appearance temperature).        Addition of inhibitors (thermodynamic or kinetic), which prevent hydrate deposition.        
Pigging is a complex and expensive operation. If no loop is available, a pig has to be inserted sub-sea using remote-operated vehicles. If more hydrates are deposited than the pig diameter is designed for, the pig might get stuck in the pipeline, resulting in costly operations and stop in production to remove the pig
Electric heating is not feasible for long-distance transport as both installation and operational costs are too high. Pigging has large operational costs.
Another method to reduce or avoid the use of hydrate inhibitor is to insulate the pipeline and reduce the diameter to increase the flow rate and thereby reduce temperature loss and water accumulation. If the pipeline is not too long, such as in the order of 1-30 km, it will be possible to keep the temperature above the hydrate formation temperature, at which hydrates form. However, this reduces the operational window of the pipeline, and it will not have capacity for future higher gas rates and cannot be operated at low gas rates. Boosting might also be required, as the pipeline pressure drop will be important due to a small sized pipeline. In addition, hydrate formation will occur during production stops and shut downs as the hydrocarbons are cooled below the formation temperature.
To avoid formation of hydrate, a hydrate inhibitor can be added, such as an alcohol (methanol or ethanol) or a glycol such as monoethylene Glycol (MEG or 1,2-ethanediol), which is inexpensive and simple to inject. However, if the water content is high, proportional large amounts of inhibitor are needed which at the receiving end will require a hydrate inhibitor regeneration process unit with sufficient capacity to recover and recycle the inhibitor.
Therefore, there is a need for removing both liquid water and water in the gas phase from a produced hydrocarbon-containing fluid, wherein the ratio of liquid and gas phase is dependent on the water vapour pressure at the prevailing temperature and pressure. The water removal in a hydrocarbon-containing gas, or the water dew-point depression, should be performed before the temperature of the fluid drops below the hydrate formation temperature. In addition, reduced quantities of hydrate inhibitors compared to prior art should be used, i.e. before long transport by pipeline subsea in cold sea water, such as 5 km or more, for example 10, 20, 30, 50, 75 or 100 km or more.
RU 2199375 concerns a method for absorption drying of hydrocarbon gas by using a primary separation step and a cooling step where the gas temperature and dew point of gas is controlled by addition of an absorbent before the cooler, and a second separation step where the absorbent is regenerated for further transport of the gas. The removal of bulk water in the first separation step reduces the load on the absorber, but with the use of an absorber at least one regeneration unit is necessary, which is undesirable in subsea installations.
U.S. Pat. No. 5,127,231 concerns the treatment of a gas from a production well by contacting the gas with a liquid phase, containing water and hydrate inhibitor, in a unit separating off a liquid phase and an additive charged gas which is transported over long distances, which may be several kilometres. A drying process is described involving a contactor with absorbent (glycol). The gas is cooled during transport before entering a heat exchanger where condensate of water solvent and additive is separated form the gas in a settlement vessel. The liquid phase is recycled to the production site. Hence, hydrate inhibitor is added during the first separation and is present during the main transport before cooling, after which the additive is separated at the end reception terminal where the gas is treated.
The methods described above make use of recirculation of anti-hydrate additive introduced during the first separation step on the well stream. This introduction of additive necessitates an absorber unit for regeneration of the additive.
It was therefore desirable to reduce the number of process units at subsea and to minimize the amount of hydrate inhibitor used, so that the gas phase from a production well that may be transported over large distances in cold water without causing hydrate formation, while requiring no or little additive regeneration when reaching a process unit.
A suitable process and system is described in prior application P61001792NO01, which describes a process and system that solves more satisfactorily the problem of how to bring a subsea well stream to a condition more suited for long distance transport with reduced requirement for hydrate inhibitor.
The process and system of P61001792NO01 can be understood by reference to FIG. 1. An uninhibited warm well stream 101 enters a first separator 110 where the gas phase goes to a gas cooler 120 which cools the well stream to a temperature above the hydrate temperature (typically 20-25° C.). The purpose of this cooler is to knock out much of the water from the gas without the need for the addition of inhibitor.
The gas phase then continues via 108 and hydrate inhibitor 191 may be injected. A second gas cooler 121 further cools the gas to a temperature near the sea temperature (0-10° C.) to further reduce the water content in the gas.
The majority of the water from 101 and 162 is separated out in 110 and sent via conduit 104 and may be re-injected in the sub-terrain formations by wellhead 140. The remaining liquid continuing in 133 consists mainly of oil and condensate, with small amounts of water. The formation of hydrates in this liquid is inhibited by the liquid stream 161, which contains mainly inhibitor (and water and condensate) if hydrate inhibitor 191 is injected to the gas phase in 108.
The purpose of this invention can thus be seen was to reduce the amount of inhibitor required to inhibit the gas flow 111 and, optionally, the liquid flow 133. This is done by separation of the bulk water in the gas phase by the use of the separators 110, 130, 131.
Although the invention of P61001792NO01 addresses the problem of minimising the amount of hydrate inhibitor used and to some extent reducing the number of process units at subsea, there are a number of problems that exist with this. There will always be water in a well stream, either solved in the gas phase or produced liquid water. When the well stream is cooled, the water in the gaseous phase will condense into liquid water. As discussed above, liquid water and hydrocarbons will form hydrates if the temperature is reduced below approx. 15-25° C., which is the case for the transport from today's subsea satellite fields. As noted above, conventional techniques prior to P61001792NO01 involved the addition of hydrate inhibitor to the entire well stream with all the further processing done further downstream. If the amount of water is large, the amount of inhibitor must be correspondingly large.
Some recent field developments include a separator at the sea bed to take out bulk water from the liquid phase. The bulk water is re-injected and thus the need for inhibitor to prevent hydrates in the pipeline is reduced considerably. At the receiving end of the well stream, the inhibitor is recycled and thus it needs regeneration (i.e. removal of water). This process is both heat demanding and takes up deck space. Reducing the amount of inhibitor required is therefore beneficial, a problem that is addressed to a large extent by the process and system of P61001792NO01.
Also, the three phase flow in the pipeline results in a large pressure drop and it imposes restrictions on the minimum flow velocity due to slugging and riser concerns. At the receiving facility, it also requires extensive separation and treatment. In particular, the gas treatment takes up much space on a platform/FPSO (floating production storage and offloading facility). The treatment of gas at the receiving facility can also be a safety concern. For smaller fields remotely located, it might therefore be smarter to route the gas from many fields to one common process facility, preferably located on land. It is therefore desirable to achieve the bulk separation of oil and gas and moving the first processing to the seabed, enabling routing the gas to one location and the liquids to another, both locations being remotely located and preferably on land. However, in order for this to be achieved it is necessary for the gas phase to satisfy minimum subsea transport specifications with respect to water content.